|Publication number||US7555391 B2|
|Application number||US 11/070,625|
|Publication date||Jun 30, 2009|
|Filing date||Mar 2, 2005|
|Priority date||Mar 4, 2004|
|Also published as||CA2558332A1, CA2558332C, EP1735642A2, EP1735642A4, US7962288, US8364406, US8407006, US9399909, US20050194185, US20050200498, US20090260876, US20110253447, US20130120154, US20130213128, WO2005086691A2, WO2005086691A3, WO2005091019A1|
|Publication number||070625, 11070625, US 7555391 B2, US 7555391B2, US-B2-7555391, US7555391 B2, US7555391B2|
|Inventors||Daniel D. Gleitman|
|Original Assignee||Halliburton Energy Services, Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (33), Non-Patent Citations (22), Referenced by (17), Classifications (22), Legal Events (3)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application claims priority to commonly owned U.S. provisional patent application Ser. No. 60/550,033, filed Mar. 4, 2004, entitled “Multiple Distributed Sensors Along A Drillpipe,” by Daniel Gleitman.
As oil well drilling becomes increasingly complex, the importance of collecting downhole data while drilling increases.
As shown in
The terms “couple” or “couples,” as used herein are intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical connection via other devices and connections. The term “upstream” as used herein means along a flow path towards the source of the flow, and the term “downstream” as used herein means along a flow path away from the source of the flow. The term “uphole” as used herein means along the drillstring or the hole from the distal end towards the surface, and “downhole” as used herein means along the drillstring or the hole from the surface towards the distal end.
It will be understood that the term “oil well drilling equipment” or “oil well drilling system” is not intended to limit the use of the equipment and processes described with those terms to drilling an oil well. The terms also encompass drilling natural gas wells or hydrocarbon wells in general. Further, such wells can be used for production, monitoring, or injection in relation to the recovery of hydrocarbons or other materials from the subsurface.
One or more force sensors 175 may be distributed along the drillpipe, with the distribution depending on the needs of the system. In general, the force sensors 175 may include one or more sensor devices to produce an output signal responsive to a physical force, strain or stress in a material. The sensor devices may comprise strain gauge devices, semiconductor devices, photonic devices, quartz crystal devices, or other devices to convert a physical force, strain, or stress on or in a material into an electrical or photonic signal. In certain embodiments, the force measurements may be directly obtained from the output of the one or more sensor devices in the force sensors 175. In other embodiments, force measurements may be obtained based on the output of the one or more sensor devices in conjunction with other data. For example, the measured force may be determined based on material properties or dimensions, additional sensor data (e.g. one or more temperature or pressure sensors), analysis, or calibration.
One or more force sensors 175 may measure one or more force components, such as axial tension or compression, or torque, along the drillpipe. One or more force sensors 175 may be used to measure one or more force components reacted by or consumed by the borehole, such as borehole-drag or borehole-torque, along the drillpipe. One or more force sensors 175 may be used to measure one or more other force components such as pressure-induced forces, bending forces, or other forces. One or more force sensors 175 may be used to measure combinations of forces or force components. In certain implementations, the drillstring may incorporate one or more sensors to measure parameters other than force, such as temperature, pressure, or acceleration.
In one example implementation, one or more force sensors 175 are located on or within the drillpipe 140. Other force sensors 175 may be on or within one or more drill collars 145 or the one or more MWD/LWD tools 150. Still other force sensors 175 may be in built into, or otherwise coupled to, the bit 160. Still other force sensors 175 may be disposed on or within one or more subs 155. One or more force sensors 175 may provide one or more force or torque components experienced by the drillstring at surface. In one example implementation, one or more force sensors 175 may be incorporated into the draw works 115, hook 120, swivel 125, or otherwise employed at surface to measure the one or more force or torque components experienced by the drillstring at the surface.
The one or more force sensors 175 may be coupled to portions of the drillstring by adhesion or bonding. This adhesion or bonding may be accomplished using bonding agents such as epoxy or fasters. The one or more force sensors 175 may experience a force, strain, or stress field related to the force, strain, or stress field experienced proximately by the drillstring component that is coupled with the force sensor 175.
Other force sensors 175 may be coupled to not experience all, or a portion of, the force, strain, or stress field experienced by the drillstring component coupled proximate to the force sensor 175. Force sensors 175 coupled in this manner may, instead, experience other ambient conditions, such as one or more of temperature or pressure. These force sensors 175 may be used for signal conditioning, compensation, or calibration.
The force sensors 175 may be coupled to one or more of: interior surfaces of drillstring components (e.g. bores), exterior surfaces of drillstring components (e.g. outer diameter), recesses between an inner and outer surface of drillstring components. The force sensors 175 may be coupled to one or more faces or other structures that are orthogonal to the axes of the diameters of drillstring components. The force sensors 175 may be coupled to drillstring components in one or more directions or orientations relative to the directions or orientations of particular force components or combinations of force components to be measured.
In certain implementations, force sensors 175 may be coupled in sets to drillstring components. In other implementations, force sensors 175 may comprise sets of sensor devices. When sets of force sensors 175 or sets of sensor devices are employed, the elements of the sets may be coupled in the same, or different ways. For example, the elements in a set of force sensors 175 or sensor devices may have different directions or orientations, relative to each other. In a set of force sensors 175 or a set of sensor devices, one or more elements of the set may be bonded to experience a strain field of interest and one or more other elements of the set (i.e. “dummies”) may be bonded to not experience the same strain field. The dummies may, however, still experience one or more ambient conditions. Elements in a set of force sensors 175 or sensor devices may be symmetrically coupled to a drillstring component. For example three, four, or more elements of a set of sensor devices or a set of force sensors 175 may spaced substantially equally around the circumference of a drillstring component. Sets of force sensor 175 or sensor devices may be used to: measure multiple force (e.g. directional) components, separate multiple force components, remove one or more force components from a measurement, or compensate for factors such as pressure or temperature. Certain example force sensors 175 may include sensor devices that are primarily unidirectional. Force sensors 175 may employ commercially available sensor device sets, such as bridges or rosettes.
In certain implementations, one or more force sensors 175 may be coupled to drillstring components that are used for drilling and that are subsequently left in the borehole 165. These drillstring components may be used in casing-while-drilling (i.e. drilling with casing) operations. The drillstring components may be included in a completed well.
In general, the force sensors 175 convert force into one or more signals. The one or more signals from the force sensors 175 may be analog or digital. In certain implementations, one or more force sensors 175 may be oriented to measure one or more of tension or compression along the drillstring (i.e. with respect to the up-hole/downhole axis). As used herein, “tensile force” means one or more of tension or compression forces along the drillstring. In these implementations, the force sensors 175 may be coupled with particular drillstring components and may include strain responsive sensor devices (e.g. strain gauges). The output of the force sensor 175 may vary based on the modulus of elasticity of the material of drillstring component coupled with the force sensor. This modulus of elasticity may be used when determining the force. In certain implementations, other inputs (e.g. tensile areas) may be used to determine tension or compression forces in one or more drillstring components from the stresses. Similarly, one or more force sensors 175 may be oriented to measure torque on the drillstring (i.e. about the up-hole/downhole axis). For example, the force sensors 175 may be coupled to diameter surfaces (e.g. inner or outer diameters) of drillstring components and may employ outputs from sensor devices (e.g., one or more strain gauges) and may consider the shear modulus of elasticity of the drillstring component material. The torques may be determined based on the stresses from the strains and other inputs (e.g. polar moment of inertia of the cross sectional area).
A portion of drillpipe 140 is schematically illustrated in
In one example system, the communications medium 205 may be located within an inner annulus of the drillpipe 140. The communications medium 205 may comprise one or more concentric layers of a conductor and an insulator disposed within the drillstring. In another example system, the drillpipe 140 may have a gun-drilled channel though at least portions of its length. In such a drillpipe 140, the communications medium 205 may be placed in the gun-drilled channel. In another example system, the communications medium 205 may be fully or partly located within a protective housing, such as a capillary tubing that runs at least a portion of the length of the drillpipe 140. The protective housing may be attached or biased to the drillpipe inner diameter or stabilized within the drillpipe bore.
The communications medium 205 may be a wire, a cable, a fluid, a fiber, or any other medium. In certain implementations, the communications medium may permit high data transfer rates. The communications medium 205 may include one or more communications paths. For example, one communications path may connect to one or more force sensors 175, while another communications path may connect another one or more sensor sensors 175. The communications medium 205 may extend from the drillpipe 140 to the subs 155, drill collar 145, MWD/LWD tools 150, and the bit 160. The communications medium 205 may include physical connectors or mating conductors to complete a transition in the communications medium 205 across drillpipe joints and other connections.
The communications medium 205 may transition from one type to another along the drillstring. For example, one or more portions of the communications medium 205 may include an LWD system communications bus. One more or portions of the communications medium 205 may comprise a “short-hop” electromagnetic link or an acoustical telemetry link. The “short-hop” electromagnetic links or acoustical telemetry link may be used to interface between drillpipe joints or across difficult-to-wire drillstring components such as mud motors. In certain implementations, the communications medium may include long-hop (i.e., from a downhole transmitter to a surface receiver) telemetry. For example, the long-hop telemetry may be mud-pulse telemetry, electromagnetic telemetry through the Earth, or acoustic telemetry through the drillstring. The long-hop telemetry may employ one or more repeaters.
A processor 180 may be used to collect and analyze data from one or more force sensors 175. This processor 180 may process the force data and provide an output that is a function of the processed or unprocessed force data. This output may then be used in the drilling process. The processor may include one or more processing units that operate together (e.g., symmetrically or in parallel) or one or more processing units that operate separately. The processing units may be in the same location or in distributed locations. The processor 180 may alternatively be located below the surface, for example, within the drillstring. The processor 180 may operate at a speed that is sufficient to be useful in the drilling process. The processor 180 may include or interface with a terminal 185. The terminal 185 may allow an operator to interact with the processor 180.
The communications medium 205 may transition to connect the drillstring to the processor 180. The transition may include a mechanical contact which may include a rotary brush electrical connection. The transition may include a non-contact link which may include an inductive couple or a short-hop electromagnetic link.
The force sensors 175 may communicate with the processor 180 through the communications medium 205. Communications over the communications medium 205 can be in the form of network communications, using, for example, Ethernet. Each of the force sensors 175 may be addressable individually or in one or more groups. Alternatively, communications can be point-to-point. Whatever form it takes, the communications medium 205 may provide high-speed data communication between the sensors in the borehole 165 and the processor 180. The speed and bandwidth characteristics of the communications medium 205 may allow the processor 180 to perform collection and analysis of data from the force sensors 175 fast enough for use in the drilling process. This data collection and analysis may be referred to as “real-time” processing. Therefore, as used herein, the term “real-time” means a speed that is useful in the drilling process.
A portion of a drillstring component is illustrated in
The electronics module 310 may have complementary features, such as threading, to engage the sensor-module receptacle 305 threading. The electronics module 310 may have a protective exterior and may have O-rings 325 to isolate it from the ambient conditions exterior to the drillpipe 140 which may include the mud flowing around drillpipe 140. At least a portion of the electronics module 310 may be inserted and removed from sensor-module receptacle 305 to permit swapping or replacement, based on the type of data to be collected in the portion of the drillpipe 140 where the force sensor 175 will be located, or for maintenance. The electronics module 310 may include a connector 330 to mate with a connector 335 in the sensor-module receptacle 305.
Force sensors 175 may also be located in the pin ends of drillstring elements, for example drillpipe joints. A cross-sectional diagram of the pin end 405 of a drillpipe joint is shown in
A cross-sectional diagram of an example sub 155 is shown in
The force sensor 175 may include “dummy” sensor devices proximately located and coupled in a manner to not respond to strain in the drillstring element. Alternatively, or in addition, one or more sensor devices 340 may be coupled to the inner bore of sub 155. The box-end of the sub 155 may be bored back to retain a box-end insert 520. The box-end insert 520 may include one or more electronics modules 310. Wiring 505 may be routed from one or more of the sensor devices 340 coupled to the exterior of sub 155 through drilled holes and through hermetic sealing connectors, for connecting or soldering to the electronics module 310. Wiring 505 may be routed from one or more sensor devices 340 coupled to the inner bore of sub 155 to the electronics module. The electronics module 310 may include a coupler to couple the force sensor 175 to the communications medium 205.
The sub 155 and box-end insert 520 may include one or more sensor devices 340 configured to measure one or more of axial tension, axial compression, torque, or bending. The box-end insert may include one or more communications couplers. The communications medium 205 may be disposed in the sub 155. As discussed above, the sub 155 may include communication equipment.
An example force sensor 175, shown schematically in
The communication coupler, which is the combination of the electronics module coupler 615 and the drillpipe coupler, performs signal transformations necessary to couple the sensor signal to the communications medium 205. One example communication coupler may re-encode the signal from the sensor device 340 or the analog-to-digital converter, include header information, and transmit the signal over the communication medium 205.
An example complementary pair of electronics module coupler and drillpipe coupler connectors 330 and 335 is shown schematically in section view in
Another example complementary pair of sensor-coupler and drillpipe-coupler connectors 330 and 335 is shown in
In another example system, the electronics module coupler connector 330 and the drillpipe-coupler connector 335 may include inductors or coils. The electronics module coupler 615 may pass current though its inductor to create an electromagnetic field indicative of the force sensor signal. The electromagnetic field, in turn, induces a current in the drillpipe coupler's inductor. In another example system, the connectors 330 and 335 may form two plates of a capacitor allowing a signal to be capacitively induced on the opposing plate. The force sensor 175 or the base of the sensor-module receptacle 305 may include a coating or insert to provide a dielectric between the connectors 820 and 905 for capacitive coupling.
An example system for detecting downhole conditions based on one or more force measurements from one or more force sensors 175 is shown in
Creating the set of expected force values (block 1005) may include receiving one or more expected forces from an external source (e.g. a user, a database, or another processor). Creating the expected-value set may include accessing simulation results such as modeling results. The modeling to create the expected force values may include torque-and-drag modeling. The torque-and-drag modeling may consider one or more of the following: mechanical and other properties of the borehole and drillstring, fluid properties, operations in-process, previous force measurements from the borehole 165 or other boreholes, or other measurements. The torque-and-drag modeling may consider the dimensions and material properties of the drillstring elements. The torque-and-drag modeling may consider borehole survey data. Other modeling may be used in creating the expected-force value set, including hydraulics modeling. Other measurements may also be used in creating the expected-force value set, including pressure measurements from one or more of the standpipe 196, points along the drillstring, or points along the borehole 165. In some implementations, an expected-value set may be created by copying one or more values from a measured-value set. In other implementations an expected-value set may be created by using values from a measured-value set and adjusting or operating upon the values in accordance with an algorithm or model. Some implementations utilizing measured-value sets to create one or more expected-value sets may use measured-value sets from a recent time window, an earlier time window, or multiple time windows. Certain example expected-value sets may be derived from trend analysis of measured-value sets, such trends being observed or calculated in reference to, for example, elapsed time, circulation time, drilling time, depth, another variable or combinations of variables.
The expected-value set may include one or more force values at one or more depths in the borehole 165. The depths may be locations of interest within the borehole 165. A set of expected values may be provided or determined corresponding to all or a portion of the drillstring path within the borehole 165.
Each expected-value set may represent one or more force profiles. A force profile may include a set of two or more forces, and a set of two or more depths, or ranges of depths, where each force corresponds to a depth or a range of depths. The force profiles may exist, may be measurable, and may be modelable along the borehole 165.
Example force profiles may include one or more drillstring axial force profiles which may represent tension or compression in the drillstring, or both. Other example force profiles may include one or more borehole-drag profiles. Borehole-drag profiles may represent the forces associated with the borehole resisting axial movement of the drillstring, and may depend upon one or more of friction profile between borehole and drillstring, drillstring dimensions and buoyant weights, borehole path and angles, hook load, and other factors. Borehole-drag profiles may include static drag (i.e., the force to be overcome to move) or dynamic drag (i.e., the force resisting movement while moving). Borehole-drag profiles may be calculated or modeled using axial force profiles. Other example force profiles may include drillstring torque profiles, which may represent the torque at points along the drillstring reflecting torque sources and reaction points including one or more of: the surface rotary drive, the bit-rock interaction, a mud motor, the drillstring-borehole interaction, and other sources or reaction points. Other example force profiles may include borehole-torque profiles, which may represent the forces, acting upon a moment arm, resisting the rotation of the drillstring. Borehole-torque profiles may depend upon one or more of: the friction profile between borehole and drillstring, the drillstring dimensions and buoyant weights, the borehole path and angles, the hook load, and other factors. Borehole-torque profiles may include static torque (i.e., the torque to be overcome to begin rotation) or dynamic torque (i.e., the torque resisting rotation while rotating). Borehole-torque profiles may be calculated or modeled using one or more of axial force profiles and drillstring torque profiles. Example force profiles may include arithmetic or other combinations or superposition of profiles.
Expected force values, or an expected force value set, may be derived from a current (e.g., most recently acquired) set of one or more measured forces, a current measured force set, or a current measured force gradient. The processor 180 or the user may derive the expected force values from these one or more measured forces or measured force gradients by extrapolating a measured gradient covering a particular depth range to a larger depth range. Likewise, the processor 180 or the user may perform such a derivation by interpolating between two measured gradients.
While drilling the borehole 165, the processor 180 may change the expected-value set to reflect changes in the well. For example, the processor 180 may change the expected-value set to reflect drilling progress (e.g. increasing depth). The processor 180 may change the expected-value set to reflect the length and properties of drillstring. The processor 180 may alter the expected-value set to account for one or more known or unknown drilling process events or conditions. Changes to the expected-value set may be consistent or inconsistent with modeling, forecasts, or experience.
When generating the expected-value set, the processor 180 may consider one or more factors impacting force on the drillstring including the dimensions of the drillstring (e.g., inner and outer diameters of joints or other portions of the drillpipe and other drillstring elements), survey path and angles of borehole 165, and dimensions of the borehole 165. The processor 180 may also consider one or more depths corresponding to one or more measured forces within the borehole 165 or the drillstring. The processor 180 may consider drilling fluid properties (e.g., flow rates, densities) and whether one or more portions of the borehole 165 are cased or open hole.
The processor 180 may be provided with or may calculate one or more depths when calculating the expected-value set. The depths may include one or more of the following: the true-vertical depth (TVD) (i.e., only the vertical component of the depth), and the measured depth (MD) (i.e., the direction-less distance from the start of the borehole or other reference point chosen such as ground level, sea level, or rig level, to the bottom of the borehole or other point of interest along the borehole). The processor 180 may be provided with planned or measured survey station data (e.g., the inclination and azimuth) for one or more points along the well path, with corresponding MD or TVD depths, and the processor 180 may use the survey station data to calculate a well path. The well path may include inclinations and azimuths for some or all points of the well, which may be derived from one or more of actual data inputs at survey stations or interpolations between.
The processor 180 may generate one or more expected-value sets for different drilling process operations. For example, the processor 180 may generate one or more expected-value sets for pick-up, slack-off, sliding, rotary drilling with weight-on-bit, sliding drilling, back-reaming, tripping, and for the case where the drillstring is rotating off-bottom. The processor may consider data or planned values for operational parameters such as hook load, rotary RPM, rotary torque, downhole weight-on-bit, downhole torque-on-bit, mud motor pressure drop, or other operational parameters. The mud motor pressure drop may be used to infer a downhole torque-on-bit. In certain implementations, the expected-value set is generated dynamically based on the current drilling process operation. In other implementations, different expected-value sets are generated for different drilling process operations. In other implantations, an expected-value set is created for one drilling process operation and modified for other drilling process operations.
An example borehole 1100 that may be modeled by the processor 180 is shown schematically in
An example expected-value set based on borehole 1100 having dimensions described above is shown in
In certain example implementations, the processor may not determine the one or more gradients (block 1020). For example, if the processor 180 is detecting at least one downhole condition which can be detected by observing absolute differences between one or more measured forces, or between one or more measured forces and one or more expected forces, it may not determine the one or more gradients.
The number and location of the force sensors 175 may affect the number of force-versus-depth data points available in the measured-value set. Additionally, a force sensor 175 that is moved from one location to another (e.g. during drilling or tripping) may provide multiple data points in a measured-value set.
Certain example implementations may include the creation of a measured-value set (block 1015) inclusive of one or more force measurements from surface sensors not actually on the drillstring, as described earlier. In such implementations one or more force measurements (e.g. tension, torque) corresponding to the top of the drillstring may be inferred from the surface sensor force measurements. At least two force-versus-depth data points may be used to determine a measured-value gradient. Where actual force-versus-depth data points are not available, the processor 180 may estimate one or more force-versus-depth data points. The processor 180 may estimate force-versus-depth data points by interpolating between data points, extrapolating gradients, or determining transitions between gradients.
In certain example system, the measured-value set of forces (e.g., measured tension/compression or torque values), the expected-value set of forces (e.g., expected tension/compression or torque values), or both may be displayed to the operator using the terminal 185. For example, the measured-value set may be juxtaposed to the expected-value set using the terminal 185, allowing the user to manually detect, identify, characterize, or locate a downhole condition. The measured-value sets and the expected-value sets may be presented to the user in a graphical format (e.g., a chart, log, plot, or series of plots) or in a textual format (e.g., a table of values). Certain example systems may include presenting an evolution of one or more of the measured-value sets and the expected-value sets to the user. For example, the system may display a series of plots to the user to demonstrate the evolution of one or more of the measured-value sets and the expected-value sets. The system may display an evolution of both the measured-value set and the expected-value set. Certain evolutions may be evolutions over time, depth, or other variables or combinations of variables.
Individual measured forces (e.g., tensions/compressions or torques) in the measured-value set may be measured in a short time window (e.g. seconds) for minimized delay in detecting of conditions. In many implementations individual measured forces in the measured-value set may be measured substantially simultaneously. As used herein, “substantially simultaneously” means only that the measurements are taken in the same time period during which conditions are not expected to change significantly, in the context of the particular operational process. Many downhole conditions (e.g., cuttings build-up) may be detected using measured-value sets, the values of which are obtained in a time window of minutes. During transient operational processes such as tripping, and for detection of events or conditions which have a faster time constant, a shorter time window for collecting and analyzing a measured-value set may be preferred. Individual measured forces along the drillstring in the measured-value set may be measured in a short time window (e.g. within a second or less), and such short-time-window measurement process may then be repeated one or more additional times during a larger time window of seconds to minutes. An averaged measured-value set may be created from averaging the multiple values for each force sensor. Other statistics may be developed for each measured force in the measured-value set. The statistics may include, for example, minimum and maximum values and standard deviation. Averaged values, optionally in conjunction with further statistics, may be preferred for use during certain operational processes in which conditions are anticipated to have a dynamic element (e.g. stick or slip during drilling).
Individual measured forces in the measured-value set may be measured sequentially. In some example implementations, the sequence by which the forces are measured may be controllable by, for example, the processor 180. For example, the sequence by which the forces are measured may be determined by an algorithm based on drilling conditions or other factors.
Example systems may provide measured versus expected forces, profiles, or gradients in different operational processes of well construction, including, for example and without limitation: on-bottom rotary drilling, sliding, tripping, off-bottom circulating, circulating up a kick, circulating pills or transitioning mud types, picking up, and slacking off.
An example system for determining if there is a downhole condition (block 1030) is shown in
The processor 180 may determine whether any of the quantities are out of range (blocks 1305) by determining if the difference between the measured property (e.g., measured tension/compression, toque, tension/compression gradient, or torque gradient) and the expected property (e.g., expected tension/compression, torque, tension/compression gradient, or torque gradient) is greater than a maximum delta for the property.
In certain implementations, the maximum delta may be determined automatically by the processor 180. In other implementations the maximum delta may be input by an operator. In other implementations, the maximum delta may be obtained from a separate processor or model. In certain implementations, the maximum delta may be determined by an operator or an independent model based on one or more measured forces.
The maximum delta determination may be based on an absolute difference versus an expected value, or it may be based on a percentage deviation from the expected value. The maximum delta may be based upon a function. For example, the maximum delta may increase or decrease with depth. The maximum delta may vary over a depth range or over an operational phase. The maximum delta determination may also be dependant on time. In certain implementations, a difference between a measured force and an expected force exceeding the maximum delta may be not be acted on unless it persists for a particular duration or longer. The maximum delta may include one or more statistical criteria, for example it may include a mean, average, or standard deviation of collected deltas over a chosen duration.
If the processor 180 determines that there is a downhole condition (block 1030), it may identify the condition (e.g. determine the type condition detected), it may characterize the downhole condition (e.g. determine the magnitude or other properties of the downhole condition), and it may locate the position of the downhole condition (e.g. determine the depth or depth interval of the detected condition) (block 1035), and it may take additional actions (block 1040).
An example system for identifying, locating, and characterizing at least one downhole condition (block 1035) is shown in
The identification and location of downhole conditions are demonstrated by reference to example expected- and measured-value sets in
The offset difference in the expected-value set (1505) and measured value set (1510) may be indicative of a downhole condition. The divergence between the expected value set and measured value set over the range shown by 1515 may be indicative of the location of the downhole condition. The difference in the expected-value and measured-value gradient over the range shown by 1515 may be indicative of a cutting build-up in the mid-horizontal section 1120 of the borehole 1100. The processor 180 may observe the offset between the expected-value set and measured value set and may indicate existence of a likely downhole condition. The processor 180 may observe the divergence between the expected value set and measured value set over the range shown by 1515 and it may indicate a likely location of the downhole condition (around measured depth range of 1515). The processor 180 may observe this gradient difference and identify the condition as a likely cutting-build up.
The cuttings build-up in the mid-horizontal section may increase the frictional drag over the interval of cuttings build-up, thus increasing the tension gradient (i.e. the change in tension per change in measured depth) measured over that interval. An increased tension gradient (from any source) over an interval may tend to increase the overall tension load measured during pick-up measured at locations from that interval up to surface, which may result in an offset difference as also shown in
The offset difference in the expected-value set (1905) and measured value set (1910) may be indicative of a downhole condition. The divergence between the expected value set and measured value set over the range shown by 1915 may be indicative of the location of the downhole condition. The difference in the expected-value and measured-value gradient over the range shown by 1915 may be indicative of a cutting build-up in the mid-horizontal section 1120 of the borehole 1100. The processor 180 may observe the offset between the expected-value set and measured value set and may indicate existence of a likely downhole condition. The processor 180 may observe the divergence between the expected value set and measured value set over the range shown by 1915 and it may indicate a likely location of the downhole condition (around measured depth range of 1915).
The processor 180 may observe the gradient difference between the expected- and measured-value sets and identify the condition as a likely cutting-build up. Such cuttings build-up may increase the frictional drag over the interval of cuttings build-up, thus increasing the torque gradient (i.e. the change in torque per change in measured depth) measured over that interval. An increased torque gradient (from any source) over an interval would tend to increase the overall torque load measured during rotation measured at locations from that interval up to surface, which may result in an offset difference as also shown in
The processor 180 may observe the offset between the expected-value set and measured value set and may indicate existence of a likely downhole condition. The processor 180 may observe the divergence between the expected value set and measured value set over the range shown by 2115 and it may indicate a likely location of the downhole condition (around measured depth range of 2115). The processor 180 may observe this difference between the measured and expected drillstring torque to represent a step-change and identify the condition as a borehole deviation. The processor 180 may determine that the likely location of the borehole deviation at or about the depth corresponding to the step-change 2115.
The downhole conditions may also be characterized by the processor 180 (block 1420). Such characterization may include the determination of a likely magnitude range of the condition. The magnitudes of the measured and expected force values and measured and expected-value gradients may be indicative (e.g., analytically through known relationships or empirically) of the characteristics of the condition. For example, the particular changes in forces or gradients may be used to estimate a revised effective friction factor for an interval. A particular change in forces or gradients may be used to estimate a particular percentage volume or cross sectional area of borehole filled in by cuttings in a cuttings bedded interval. In other examples, processor 180 may characterize the interval length of a borehole deviation such as a swelling shale. In yet other examples, the processor 180 may characterize the criticality (e.g. from a drill string integrity standpoint) of a borehole deviation such as a keyseat or severe dogleg. The processor 180 may use additional force data from force sensors along the drillstring, such as bending forces, in certain characterizations.
The processor 180 or the user may use a combination of measured force types in detecting, identifying, locating, or characterizing one or more downhole conditions. For example, the processor 180 or the user may use one or more of the following to detect, identify, locate, or characterize a downhole condition: the measured tensile force data and associated expected data, and measured torque data and associated expected data, tensile force and torque gradients and respective gradient differences. As can be seen from
The processor 180 may use other data from drilling rig site sensors and drillstring sensors to detect, identify, locate, or characterize one or more downhole conditions. For example, pressure sensor measured value sets from pressure sensors along the drillstring and expected pressure value sets, differences between the pressure sets, gradients of respective pressure sets, and pressure gradient differences, may for certain downhole conditions be depth-correlated with respective force sensor value sets, their differences, gradients, and gradient differences. In another example, formation log data (e.g. from an MWD/LWD tool 150 being run on the drillstring) may be depth correlated with certain downhole conditions. For example, as discussed with respect to
Certain additional downhole conditions may be detected, identified, located, or characterized by similar techniques. Example conditions that may be detected are lost circulation, which may cause mild differential sticking (i.e. not to the point of a stuck drillstring) or a stuck drill sting. Multiple force measurements may be made along the drillstring, and compared to expected values, in the process of getting a drillstring unstuck. Such a process may involve applying one or more of torque, tension, compression, or impact (e.g. jarring) on the drillstring from the surface. The transmission of such torque, tension, compression, or impact down the drillstring to the stuck point may be subject to similar borehole drag, borehole-torque, and borehole conditions consuming portions of the transmitted forces. Comparing the expected and measured forces along the drillstring may be used to improve the control and efficacy of such processes.
As noted earlier, in certain implementations, measured-value sets may be used directly to provide one or more expected values or an expected-value set for purposes of the methods discussed. For example the detection, identification, location, and characterization of a borehole deviation such as the deviation discussed with regard to
The processor 180 may perform additional actions after detecting a downhole condition (block 1040). As shown in
As noted earlier, in certain implementations one or more of the measured-value set of forces (e.g., measured tension/compression or torque values) and the expected-value set of forces may be provided to the user for manual interpretation through comparison of tables, plots, logs, graphs, or the like. In these cases the processor 180 may be used in the collection of measured data, and the user may manually (e.g., without reliance on the processor) perform the steps outlined above of detecting, identifying, locating, and characterizing a downhole condition. In these cases the processor 180 may be used in the collection of measured data and the displaying or otherwise providing such data in the context of expected values, and the user may manually perform the steps outlined above of detecting, identifying, locating, and characterizing a downhole condition.
The processor 180 may also modify the expected-value set (block 1045), as shown in
The present invention is therefore well-adapted to carry out the objects and attain the ends mentioned, as well as those that are inherent therein. While the invention has been depicted, described and is defined by references to examples of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration and equivalents in form and function, as will occur to those ordinarily skilled in the art having the benefit of this disclosure. The depicted and described examples are not exhaustive of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US3223184||May 31, 1961||Dec 14, 1965||Sun Oil Co||Bore hole logging apparatus|
|US3864968 *||Nov 19, 1973||Feb 11, 1975||Schlumberger Technology Corp||Force-measuring apparatus for use in a well bore pipe string|
|US4273212||Jan 26, 1979||Jun 16, 1981||Westinghouse Electric Corp.||Oil and gas well kick detector|
|US4379493||May 22, 1981||Apr 12, 1983||Gene Thibodeaux||Method and apparatus for preventing wireline kinking in a directional drilling system|
|US4384483||Aug 11, 1981||May 24, 1983||Mobil Oil Corporation||Preventing buckling in drill string|
|US4535429||Jul 11, 1983||Aug 13, 1985||Nl Sperry-Sun, Inc.||Apparatus for signalling within a borehole while drilling|
|US4553428||Nov 3, 1983||Nov 19, 1985||Schlumberger Technology Corporation||Drill stem testing apparatus with multiple pressure sensing ports|
|US4697650||Sep 24, 1984||Oct 6, 1987||Nl Industries, Inc.||Method for estimating formation characteristics of the exposed bottomhole formation|
|US4779852||Aug 17, 1987||Oct 25, 1988||Teleco Oilfield Services Inc.||Vibration isolator and shock absorber device with conical disc springs|
|US4791797||Feb 17, 1988||Dec 20, 1988||Nl Industries, Inc.||Density neutron self-consistent caliper|
|US4805449||Dec 1, 1987||Feb 21, 1989||Anadrill, Inc.||Apparatus and method for measuring differential pressure while drilling|
|US5156223||May 14, 1991||Oct 20, 1992||Hipp James E||Fluid operated vibratory jar with rotating bit|
|US5563512||Jun 14, 1994||Oct 8, 1996||Halliburton Company||Well logging apparatus having a removable sleeve for sealing and protecting multiple antenna arrays|
|US5679894||Oct 10, 1995||Oct 21, 1997||Baker Hughes Incorporated||Apparatus and method for drilling boreholes|
|US5798488||Mar 27, 1995||Aug 25, 1998||Gec Marconi Limited||Acoustic sensor|
|US5804713||Sep 20, 1995||Sep 8, 1998||Sensor Dynamics Ltd.||Apparatus for sensor installations in wells|
|US5886303||Oct 20, 1997||Mar 23, 1999||Dresser Industries, Inc.||Method and apparatus for cancellation of unwanted signals in MWD acoustic tools|
|US5995020||Oct 17, 1995||Nov 30, 1999||Pes, Inc.||Downhole power and communication system|
|US6026914||Jan 28, 1998||Feb 22, 2000||Alberta Oil Sands Technology And Research Authority||Wellbore profiling system|
|US6079505||Apr 21, 1995||Jun 27, 2000||Institut Francais Du Petrole||System and method for the acquisition of physical data linked to a drilling operation in progress|
|US6279392||Nov 16, 1999||Aug 28, 2001||Snell Oil Company||Method and system for distributed well monitoring|
|US6325123||Dec 23, 1999||Dec 4, 2001||Dana Corporation||Tire inflation system for a steering knuckle wheel end|
|US6464021||Dec 30, 1999||Oct 15, 2002||Schlumberger Technology Corporation||Equi-pressure geosteering|
|US6516880||Sep 29, 2000||Feb 11, 2003||Grant Prideco, L.P.||System, method and apparatus for deploying a data resource within a threaded pipe coupling|
|US6516898||Aug 4, 2000||Feb 11, 2003||Baker Hughes Incorporated||Continuous wellbore drilling system with stationary sensor measurements|
|US6568486||Sep 6, 2000||May 27, 2003||Schlumberger Technology Corporation||Multipole acoustic logging with azimuthal spatial transform filtering|
|US6581455||Nov 1, 2000||Jun 24, 2003||Baker Hughes Incorporated||Modified formation testing apparatus with borehole grippers and method of formation testing|
|US6670880||Mar 23, 2001||Dec 30, 2003||Novatek Engineering, Inc.||Downhole data transmission system|
|US20020017386||Oct 4, 2001||Feb 14, 2002||Halliburton Energy Services, Inc.||Methods of downhole testing subterranean formations and associated apparatus therefor|
|US20020074165||Aug 30, 2001||Jun 20, 2002||Chack Fan Lee||Drilling process monitor|
|US20030209365||Mar 21, 2003||Nov 13, 2003||Geoff Downton||Recalibration of Downhole Sensors|
|US20050024231 *||Jun 14, 2004||Feb 3, 2005||Baker Hughes Incorporated||Apparatus and methods for self-powered communication and sensor network|
|GB2235540A||Title not available|
|1||"IntelliPipe(TM) Technology: Wired For Speed and Durability," U.S. Department of Energy Office of Fossil Energy http;//fossil.energy.gov/news/techlines/03/tl-intellipipe-rmotctest.html, Jun. 5, 2003.|
|2||"Telemetry Drill Pipe: Enabling Technology for the Downhole Internet," http://www.intellipipe.com/brochures.asp, Intellipipe Brochure 1.|
|3||"Telemetry Drill Pipe: Enabling Technology for the Downhole Internet," http://www.intellipipe.com/brochures.asp, Intellipipe Brochure 2.|
|4||A. Judzis, T. S. Green, G. M. Hoversten, and A. D. Black, "Seismic While Drilling for Enhanced Look-Ahead-Of-Bit Capabilities-Case Study of Successful Mud Pulse Coupling Demonstration," Society of Professional Engineers, SPE 63194, pp. 1-4, Presented at the 2000 SPE Annual Technical Conference and Exhibition Held in Dallas, Texas, Oct. 1-4, 2000.|
|5||A. Leseultre, et al., An Instrumented Bit: A Necessary Step to the Intelligent BHA, SPE 39341, pp. 457-463.|
|6||A.J. Mansure, et al., Interpretation of Diagnostics-While-Drilling Data, SPE 84244, 2003, pp. 1-13.|
|7||C.A. Johancsik, et al., Torque and Drag in Directional Wells-Prediction and Measurement, Journal of Petroleum Technology, pp. 987-992 (Jun. 1984).|
|8||Chirs Ward and Espen Andreassen, "Pressure-While-Drilling Data Improve Reservoir Drilling Performance," SPE Drilling & Completion, Mar. 1998, pp. 19-24.|
|9||Cook, R.L., et al., First Real Time Measurements of Downhole Vibrations, Forces, and Pressures Used to Monitor Directional Drilling Operations, SPE 18651, 1989, pp. 283-290.|
|10||Daniel C. Minette, Eric Molz, "Utilizing Acoustic Standoff Measurements to Improve the Accuracy of Density and Neutron Measurements," Society of Petroleum Engineers Inc., SPE 56447, pp. 1-14, Presented at the 1999 SPE Annual Technical Conference and Exhibition Held in Houston, Texas, Oct. 3-6, 1999.|
|11||E Alan Coats, Marty Paulk, Chris Dalton, "Wired Composite Tubing Reduces Drilling Risk," Drilling Contractor, pp. 22-23, Jul./Aug. 2002.|
|12||Falconer, et al., Applications of a Real Time Wellbore Friction Analysis, SPE 18649, 1989, pp. 265-274.|
|13||Frank Reiber, et al., On-Line Torque & Drag: A Real-Time Drilling Performance Optimization Tool, SPE 52836, 1999, pp. 1-10.|
|14||G.E. Guillen and W.G. Lesso Jr., The Use of Weight on Bit, Torque, and Temperature To Enhance Drilling Efficiency, SPE 12165, 1983, pp. 1-12.|
|15||Heisig, G., et al., Downhole Diagnosis of Drilling Dynamics Data Provides New Level Drilling Process Control to Driller, SPE 49206, 1998, pp. 649-658.|
|16||Ho, H-S., An Improved Modeling Program for Computing the Torque and Drag in Directional and Deep Wells, SPE 18047, 1988, pp. 407-418.|
|17||J.T. Finger, et al., Development of a System for Diagnostic-While-Drilling (DWD), SPE 79884, 2003, pp. 1-9.|
|18||Johancsik, C.A., et al., Torque and Drag in Directional WellsPrediction and Measurement, SPE 11380, 1984, pp. 201-208.|
|19||Michael J. Jellison and David R. Hall, "Intelligent Drill Pipe Creates the Drilling Network," SPE International, SPE 80454, pp. 1-8, Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, Apr. 15-17, 2003.|
|20||Paul Pastusek, et al., A Model for Borehole Oscillations, SPE 84448, 2003, pp. 1-16.|
|21||Tom Gaynor, et al., Quantifying Tortuosities by Friction Factors in Torque and Drag Model, SPE 77617, 2002, pp. 1-8.|
|22||Wolf, S.F., et al., Field Measurements of Downhole Drillstring Vibrations, SPE 14330, 1985, pp. 1-12.|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US8188882 *||Apr 8, 2008||May 29, 2012||Baker Hughes Incorporated||Depth measurement by distributed sensors|
|US8376065||Sep 14, 2009||Feb 19, 2013||Baker Hughes Incorporated||Monitoring drilling performance in a sub-based unit|
|US8775085 *||Feb 17, 2009||Jul 8, 2014||Baker Hughes Incorporated||Distributed sensors for dynamics modeling|
|US9051781||May 22, 2012||Jun 9, 2015||Smart Drilling And Completion, Inc.||Mud motor assembly|
|US9218315 *||Nov 9, 2012||Dec 22, 2015||Rigaku Corporation||X-ray analysis apparatus|
|US9512708||Jun 29, 2011||Dec 6, 2016||Halliburton Energy Services, Inc.||System and method for automatic weight-on-bit sensor calibration|
|US9631446||Mar 5, 2015||Apr 25, 2017||Impact Selector International, Llc||Impact sensing during jarring operations|
|US9745799||Apr 27, 2015||Aug 29, 2017||Smart Drilling And Completion, Inc.||Mud motor assembly|
|US20080202810 *||Feb 13, 2008||Aug 28, 2008||Michael Joseph John Gomez||Apparatus for determining the dynamic forces on a drill string during drilling operations|
|US20080252479 *||Apr 8, 2008||Oct 16, 2008||Baker Hughes Incorporated||Depth measurement by distributed sensors|
|US20090216455 *||Feb 17, 2009||Aug 27, 2009||Baker Hughes Incorporated||Distributed sensors for dynamics modeling|
|US20100032210 *||Sep 14, 2009||Feb 11, 2010||Baker Hughes Incorporated||Monitoring Drilling Performance in a Sub-Based Unit|
|US20130138382 *||Nov 9, 2012||May 30, 2013||Rigaku Corporation||X-ray analysis apparatus|
|US20140196949 *||Jun 29, 2012||Jul 17, 2014||University Of Calgary||Autodriller system|
|EP2478183A4 *||Sep 14, 2010||May 10, 2017||Baker Hughes Inc||Monitoring drilling performance in a sub-based unit|
|WO2011032133A2 *||Sep 14, 2010||Mar 17, 2011||Baker Hughes Incorporated||Monitoring drilling performance in a sub-based unit|
|WO2011032133A3 *||Sep 14, 2010||Jun 16, 2011||Baker Hughes Incorporated||Monitoring drilling performance in a sub-based unit|
|U.S. Classification||702/9, 73/152.46|
|International Classification||E21B17/00, E21B17/02, E21B47/01, G01V9/00, G01V3/00, G06F15/00, G01V1/40|
|Cooperative Classification||E21B17/028, E21B47/01, E21B47/12, E21B17/003, G06F17/40, E21B47/06, E21B47/00, E21B47/065, G01V3/00|
|European Classification||E21B17/00K, E21B47/01, E21B17/02E, E21B47/12|
|Mar 2, 2005||AS||Assignment|
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:GLEITMAN, DANIEL;REEL/FRAME:016356/0131
Effective date: 20050302
|Oct 4, 2012||FPAY||Fee payment|
Year of fee payment: 4
|Jul 25, 2016||FPAY||Fee payment|
Year of fee payment: 8